This invention relates generally to a method for producing hydrogen. More particularly, the present invention relates to a method utilizing fossil fuels, biomass, petroleum coke, or any other carbon bearing fuel to produce hydrogen for power generation which minimizes or eliminates the release of carbon dioxide (CO2).
Fossil fuel power stations conventionally use steam turbines to convert heat into electricity. Conversion efficiencies of new steam power stations can exceed 40% on a lower heating value basis (LHV). New supercritical steam boiler designs, relying on new materials, allow higher steam temperatures and pressures, providing efficiencies of close to 50% LHV and further improvements might be expected. Significant advancements have also been made in combined cycle gas turbines (CCFTs). A gas turbine can withstand much higher inlet temperatures than a steam turbine. This factor produces considerable increases in overall efficiency. The latest designs currently under construction can achieve efficiencies of over 60% LHV. All of these improvements in efficiency translate into a reduction of the specific emissions on a per megawatt basis.
Although substantial reductions in emissions of CO2 could be achieved by increase in efficiency of energy conversion and utilization, such reductions may not be sufficient to achieve atmospheric CO2 stabilization. Therefore, efforts have also been directed towards the capture and sequestration of the CO2 emitted by fossil fuel-fired power plants. Sequestration of CO2 entails the storage or utilization of CO2 in such a way that it is kept out of the atmosphere. Capture of the CO2 may be performed prior to or after combustion of the fuel. Production of CO2 may be minimized during combustion of the fuel.
The fuel may be de-carbonized prior to combustion by extracting H2 from the hydrocarbon fuel, the CO2 being captured and the H2 being subsequently combusted. Steam reforming, gasification and partial oxidation are examples of such processes. The most promising de-carbonization approach is via Integrated Gasification Combined Cycle (IGCC). With IGCC, coal is gasified to produce a synthesis gas, which is then catalytically water gas shifted in order to increase the CO2 concentration. This shifted synthesis gas is quenched, and CO2 is removed with a solvent, such as selexol, in a process analogous to the amine flue gas scrubbing. Separated CO2, is dried and compressed to supercritical conditions for pipeline transport. The cleaned synthesis gas, now rich in H2, is fired in a combustion turbine and waste heat from the gasification quench and from the GT fuel gas is recovered to raise steam and feed a steam turbine. Because the CO2 is removed from the concentrated and pressurized synthesis gas stream, the incremental capital cost and energy penalty is lower than for the capture of CO2 from flue gas. A study by Parsons Energy and Chemical Group, Inc. has shown an incremental energy penalty of about 14% and the cost of CO2 mitigation of about $18/tonne (Owens, et al., 2000).
Combustion of the fossil fuel in O2/recycled flue gas eliminates the need for capture of CO2 by using pure or enriched oxygen instead of air for combustion. A substantial energy penalty is incurred using this process due to the large power requirements of producing pure oxygen.
Alternatively, separation of CO2 after combustion with air can be accomplished by a variety of techniques. The most well established method today is removal from the flue gas stream by amine solvent scrubbing in an absorption-stripping process. Such processes are already applied commercially to coal-fired boilers for the purpose of producing CO2 for industrial or food industry use. Unfortunately, substantial capital equipment is required. The efficiency of the power plant is significantly reduced by the energy required to regenerate the solvent. Studies of amine scrubbing technology applied to a U.S. utility boiler case indicate that capital investment is on the order of the original power plant and energy efficiency is reduced by 41%.